In the production of minerals, such as oil and gas, certain properties of a subterranean reservoir must be determined. One of the most important of these properties is the permeability of the reservoir. Permeability is a measure of the ability of fluids to pass through porous media. The original work on permeability was carried out by H. Darcy, who studied the flow rates of springs at Dijon, France. Muskat and Boset advanced the work of Darcy, their efforts culminating in the formulation of Darcy's law: ##EQU1## where: Q=rate of flow
K=permeability PA1 (P.sub.1 -P.sub.2)=pressure drop across sample PA1 A=cross-sectional area of sample PA1 L=length of sample PA1 .mu.=viscosity of fluid.
When a single fluid phase completely saturates the pore space of a porous media, permeability is referred to as absolute permeability. The effective permeability refers to saturations of less than 100 percent. The terms K.sub.o, K.sub.w and K.sub.g are used to designate the effective permeability with respect to oil, water and gas, respectively. Relative permeability is the ratio of effective permeability for a particular fluid at a given saturation to a base permeability.
As demonstrated by Darcy's law, the permeability of a material is inversely proportional to the flow resistance offered by the material. Normally, permeability is determined by taking core samples from the reservoir and carrying out well-defined measurement techniques on the samples. There are several techniques available for making such measurements, many of which are described in PETROLEUM PRODUCTION ENGINEERING-DEVELOPMENT by L. C. Uren, Fourth Edition, McGraw-Hill Book Company, Inc., 1956, pps. 660-669. Another standard reference is American Petroleum Institute, API RECOMMENDED PRACTICE FOR CORE-ANALYSIS PROCEDURE, API RP40, 1960.
In addition to these well known techniques, a more recently applied technique involves the use of computed tomography (CT) technology. Although only recently applied in the area of energy research, CT technology has been used in the medical field for several years. CT scanning instruments produce a cross-sectional view through the subject material along any chosen axis. The advantages of CT scanning over conventional radiography is found in its ability to display the electron density variations within the object scanned in a two-dimensional X-ray image. In medical CT scanners, an X-ray source and a detector array circle a patient in a period of about 2 to 9 seconds to produce an image having a maximum resolution of 0.25 mm in the X-Y plane. This plane can be moved in discrete intervals to obtain information in three dimensions. For more details of such medical CT scanners, reference may be made to U.S. Pat. No. 4,157,472 issued to Beck, Jr. and Barrett and U.S. Pat. No. 4,399,509 issued to Hounsfield.
Several other applications of CT scanning can also be made. For example, in an article entitled, "Computed Tomographic Analysis of Meteorite Inclusions", Science, pps. 383-384, Jan. 28, 1983, there is described the non-destructive testing of meteorites for isotopic anomalies in calcium- and aluminum-rich inclusions of heterogeneous materials, such as Allende. The CT scanning equipment described in the article is the Deltascan 2020 from Technicare. In a further application, CT scanning has been applied to the non-destructive testing of wood materials, such as for disease living in trees, see U.S. Pat. No. 4,283,629 issued to Habermehl. In a yet further application, CT scanning has been applied to the examination of non-living objects, such as motors, ingots, pipes, etc., see U.S. Pat. No. 4,422,177 issued to Mastronardi, et al.
More recently, CT scanning technology has been applied to the field of energy research for examining the interior of stationary or slowly changing earth materials, such as coal, shale and drilling cores. Processes involved in coal gasification and combustion have been monitored using time-lapse CT imagery to observe changes in density (e.g. thermal expansion, fracturing, emission of gases, consumption by combustion and the like) during progressive heating in a controlled atmosphere. Core flooding experiments can now be carried out with CT scanning to aid in enhanced oil recovery and fluid mobility control. For example, the permeability of materials within core samples to various fluids at varying conditions of temperature and pressure can be determined. Such experiments involve flushing a fluid through a core sample and monitoring the shape of the fluid fronts. By subtracting the images of the cores before and after flooding, the exact shape of the fluid front is determined. Such core flooding experiments allow the interior of the core sample to be observed without disturbing the sample. The sweep efficiency and flow paths of fluids of interest may now be studied on the scale of millimeters. The penetration of X-rays allows experiments to be performed with up to four-inch diameter cores samples.
Drilling fluids can be analyzed by CT scanning as such fluids are characterized by high-density brines, various organics and several compositionally different weighting agents. Formation damage can be investigated since CT scanning can detect migration of clays, absorption of organics and the reversibility of completion fluid penetration. Shale oil recovery can also be aided as CT scanning could detect penetration by solvents and could directly measure structure changes on retorting.
U.S. Pat. No. 4,649,483, issued to Dixon, discloses a method for determining fluid saturation in a porous media through the use of CT scanning. Multi-phase fluid saturation in a sample of porous media is determined through computer tomographic scanning. The sample is scanned with X-rays of differing energies in both the fluid saturated and the fluid extracted states. Each of the extracted fluids is also scanned at differing X-ray energies. The computed tomographic images produced are utilized in the determination of the X-ray mass attenuation coefficients for the sample and the extracted fluids. From these mass attenuation coefficients, the weight fractions and volume fractions of each of the extracted fluids are determined. U.S. Pat. No. 4,649,483 is incorporated by reference in its entirety for all that it discloses.
U.S. Pat. No. 4,688,238, issued to Sprunt et al. discloses a method for using CT scanning over a range of confining pressures on a core sample to determine pore volume change, pore compressibility and core fracturing. A core sample with a surrounding elastic jacket is placed in a confining pressure cell. Pressure is applied to the cell to press the jacket into contact with the surface of the sample. The pressure in the cell is increased stepwise over a plurality of pressure points. The sample is scanned at a plurality of locations with X-rays at each of the pressure points. Computed tomographic images of the sample are produced for each of the X-ray scans. The conformance of the jacket to the sample is determined from these computed tomographic images. From such conformance, a range of confining pressures is determined over which pore volume and pore compressibility of the sample are measured without being affected by improper conformance of the jacket to the surface of the sample. Also rock fracturing is determined form the pressure at which crushing of the sample destroys permeable channels within the sample and results in a permeability measurement that is lower than the actual permeability measurement.
Relative permeability plays a very important role in describing the fluid flow in oil and gas reservoirs. Two methods of measurement are practiced by industry; namely, steady-state and dynamic displacement. In each method a cylindrical core is saturated with water or brine, then oil flooded to irreducible water saturation. Subsequently, the core is waterflooded or brine flooded and the pressure drop across the core is measured along with the oil and water or brine production. The average saturations within the core are determined from the overall material balance. The steady-state method requires lengthy measurement times because it requires stabilization of the fluid flow. The dynamic displacement method overcomes this, however, it suffers from capillary end effects. Hence the displacement method is generally only effective for high flow rates.
U.S. Pat. No. 4,672,840, issued to Cullick, discloses a method and system for determining fluid volumes of a two-phase effluent flow through a porous material in order to determine permeability characteristics. A two-phase flow condition is established through the porous material, such as a core sample taken from a subterranean hydrocarbon-bearing reservoir. One phase is a liquid hydrocarbon phase, the other an insoluble displacing liquid phase. After exiting the core sample, the two-phase fluid is collected in a container where it separates into an overlying fluid phase, such as an oil phase, and an underlying fluid phase, such as a water phase. A fluid level monitor is positioned in the container. When the air-fluid interface at the top of the overlying fluid phase rises to a first position in the upper portion of the container, drainage of the underlying fluid phase is initiated. The time is measured during which the fluid-fluid interface of the overlying and underlying fluid phases is lowered to a second position near the bottom of the container. The time is also measured during which the air-water interface of the top of the overlying fluid phase is lowered to the same second position near the bottom of the container. The volumes of each of the two fluid phases are determinable from the time measurements and the drainage flow rate of the fluid, such volumes being representative of fluid saturation in the core sample from which core sample permeability is thus determined.
U.S. Pat. No. 4,868,751, issued to Dogru et al., relates to a method for determining relative permeability of a core sample taken from a subterranean hydrocarbon-bearing reservoir. In the method disclosed therein, pressure and fluid saturation are measured at a plurality of corresponding positions along the core before and during fluid flooding of the core. From these measurements the relative permeability of the reservoir is determined. At the start of the relative permeability measurement, the core is fully saturated with a known weight or volume of a saturating fluid, such as an oil or a brine. Dual energy X-ray CT scans are taken at a plurality of scan positions. Thereafter, the core saturation is altered through the core by flowing a displacing fluid, other than that with which the core is saturated, such as an oil, water or brine, and both saturation and pressure measurements made. U.S. Pat. No. 4,868,751 is hereby incorporated by reference for all that it discloses.
Three-phase relative permeability characteristics of reservoir rocks are usually determined from one of several mathematical models based on two-phase relative permeability data. There is a very limited amount of three-phase data available to test the validity of these models. Procedures available to industry for obtaining three-phase data are complex, and in many instances, the assumptions and errors in generating the data are suspect. As such, a need exists to design and develop a test system and method for obtaining reliable three-phase flow saturation data.
It is therefore an object of the present invention to provide a new method and system for determining the relative permeability of a subterranean reservoir which can be used to determine three-phase relative permeability characteristics of core samples obtained from such a reservoir.